There are three types of bits that are generally used to drill through subterranean formations. These bit types are: (a) percussion bits (also called impact bits); (b) rolling cone bits, including tri-cone bits; and (c) drag bits or fixed cutter rotary bits (including core bits so configured), the majority of which currently employ diamond or other superabrasive cutters, polycrystalline diamond compact (PDC) cutters being most prevalent. There also exist so-called “hybrid” bits, which include both fixed cutters and rolling cones or other rolling cutting components.
In addition, there are other structures employed downhole, generically termed “tools” herein, which are employed to cut or enlarge a borehole or which may employ superabrasive cutters, inserts or plugs on the surface thereof as cutters or wear-prevention elements. Such tools might include, merely by way of example, reamers, stabilizers, tool joints, wear knots and steering tools. There are also formation cutting tools employed in subterranean mining, such as drills and boring tools.
Percussion bits are used with boring apparatus known in the art that moves through a geologic formation by a series of successive impacts against the formation, causing a breaking and loosening of the material of the formation. It is expected that the cutter of the invention will have use in the field of percussion bits.
Bits referred to in the art as rock bits, tri-cone bits or rolling cone bits (hereinafter “rolling cone bits”) are used to bore through a variety of geologic formations, and demonstrate high efficiency in firmer rock types. Prior art rolling cone bits tend to be somewhat less expensive than PDC drag bits, with limited performance in comparison. However, they have good durability in many hard-to-drill formations. An exemplary prior art rolling cone bit is shown in FIG. 2. A typical rolling cone bit operates by the use of three rotatable cones oriented substantially transversely to the bit axis in a triangular arrangement, with the narrow cone ends facing a point in the center of the triangle that they form. The cones have cutters formed or placed on their surfaces. Rolling of the cones in use due to rotation of the bit about its axis causes the cutters to imbed into hard rock formations and remove formation material by a crushing action. Prior art rolling cone bits may achieve a rate of penetration (ROP) through a hard rock formation ranging from less than one foot per hour up to about thirty feet per hour. It is expected that the cutter of the invention will have use in the field of rolling cone bits as a cone insert for a rolling cone, as a gage cutter or trimmer, and on wear pads on the gage.
A third type of bit used in the prior art is a drag bit or fixed-cutter bit. An exemplary drag bit is shown in FIG. 1. The drag bit of FIG. 1 is designed to be turned in a clockwise direction (looking downward at a bit being used in a hole, or counterclockwise if looking at the bit from its cutting end as shown in FIG. 1) about its longitudinal axis. The majority of current drag bit designs employ diamond cutters comprising polycrystalline diamond compacts (PDCs) mounted to a substrate, typically of cemented tungsten carbide (WC). State-of-the-art drag bits may achieve an ROP ranging from about one to in excess of one thousand feet per hour. A disadvantage of state-of-the-art PDC drag bits is that they may prematurely wear due to impact failure of the PDC cutters, as such cutters may be damaged very quickly if used in highly stressed or tougher formations composed of limestones, dolomites, anhydrites, cemented sandstones interbedded formations such as shale with sequences of sandstone, limestone and dolomites, or formations containing hard “stringers.” It is expected that the cutter of the invention will have use in the field of drag bits as a cutter, as a gage cutter or trimmer, and on wear pads on the gage.
As noted above, there are additional categories of structures or “tools” employed in boreholes, which tools employ superabrasive elements for cutting or wear prevention purposes, including reamers, stabilizers, tool joints, wear knots and steering tools. It is expected that the cutter of the present invention will have use in the field of such downhole tools for such purposes, as well as in drilling and boring tools employed in subterranean mining.
It has been known in the art for many years that PDC cutters perform well on drag bits. A PDC cutter typically has a diamond layer or table formed under high temperature and pressure conditions to a cemented carbide substrate (such as cemented tungsten carbide) containing a metal binder or catalyst such as cobalt. The substrate may be brazed or otherwise joined to an attachment member such as a stud or to a cylindrical backing element to enhance its affixation to the bit face. The cutting element may be mounted to a drill bit either by press-fitting or otherwise locking the stud into a receptacle on a steel-body drag bit, or by brazing the cutter substrate (with or without cylindrical backing) directly into a preformed pocket, socket or other receptacle on the face of a bit body, as on a matrix-type bit formed of WC particles cast in a solidified, usually copper-based, binder as known in the art.
A PDC is normally fabricated by placing a disk-shaped cemented carbide substrate into a container or cartridge with a layer of diamond crystals or grains loaded into the cartridge adjacent one face of the substrate. A number of such cartridges are typically loaded into an ultra-high pressure press. The substrates and adjacent diamond crystal layers are then compressed under ultra-high temperature and pressure conditions. The ultra-high pressure and temperature conditions cause the metal binder from the substrate body to become liquid and sweep from the region behind the substrate face next to the diamond layer through the diamond grains and act as a reactive liquid phase to promote a sintering of the diamond grains to form the polycrystalline diamond structure. As a result, the diamond grains become mutually bonded to form a diamond table over the substrate face, which diamond table is also bonded to the substrate face. The metal binder may remain in the diamond layer within the pores existing between the diamond grains or may be removed and optionally replaced by another material, as known in the art, to form a so-called thermally stable diamond (“TSD”). The binder is removed by leaching or the diamond table is formed with silicon, a material having a coefficient of thermal expansion (CTE) similar to that of diamond. Variations of this general process exist in the art, but this detail is provided so that the reader will understand the concept of sintering a diamond layer onto a substrate in order to form a PDC cutter. For more background information concerning processes used to form polycrystalline diamond cutters, the reader is directed to U.S. Pat. No. 3,745,623, issued on Jul. 17, 1973, in the name of Wentorf, Jr. et al.
Conventional rotary drill bits using polycrystalline diamond compacts (PDCs) disposed on the bit face in order to produce shearing forces in the formation to be cut. Typically, these cutters are angularly positioned on the face of the drill bit according to the formation material that they are designed to cut.
In drag bits, such as illustrated in FIG. 1, positive rake cutters have an angle of inclination in the direction of bit rotation of greater than 90°. That is, positive rake cutters lean forward, or lean in the direction of bit rotation, with the included angle between the cutter face and the formation in front of it is greater than 90°. Such positive rake cutters tend to dig into the formation material, as they do not put additional compressional stresses in formation, which would give it a higher effective strength. The rotation and weight on the drill bit encourages such positive rake cutters to cut into the formation to their fully exposed depth, which could risk stalling of the bit. However, the hardness of the formation material may resist full depth penetration by a positive rake cutter. Therefore, in relatively hard material a positive rake cutter will typically not invade the formation material to its full depth, although stalling of the drill bit may still be a problem.
Conversely, a drill bit having positive rake cutters used in a formation having greater plasticity will likely result in full depth penetration of the positive rake cutters, resulting in the drill bit requiring more torque to turn the drill bit and causing the bit to stall. Accordingly, drill bits designed primarily for use in formations having greater plasticity typically use cutters having a negative rake.
The face of a negative rake cutter has an angle of inclination or included angle relative to the formation that is less than 90°, or opposite to that of a positive rake cutter. In use, a negative rake cutter has a tendency to ride along the surface of the formation giving the cutter a higher effective strength and more plasticity, resisting entry into the formation for making a shallow cut as a result of the weight on the drill bit. While negative rake cutters resist stalling of the drill bit in plastic formations because of lower aggressiveness, the linear rate of cut for a drill bit having negative rake cutters is typically less than that of the rate of cut for a bit having positive rake cutters.
Referring to FIG. 3 of the drawings, it should be noted that, while the angle of inclination of a cutting surface relative to the formation 18 is determinative of whether a particular cutter is classified as positive or negative rake cutters, the contact between the formation 18 and a cutter does not occur on a horizontal path. Rather, since a drill bit is rotating and moving downward into the formation as the borehole is cut, the cutting path followed by an individual cutter on the surface of the bit follows a helical path, as conceptually shown with respect to bit 10 depicted in FIG. 3. Bit 10 is illustrated having a longitudinal axis or centerline 24 that coincides with and extends into the longitudinal axis of a borehole 26. For illustrative purposes, bit 10 is shown having a single cutter 28 affixed on the exterior surface of the drill bit 10. It should be understood that a bit typically employs numerous cutters, but for the purposes of illustrating the helical path followed by an individual cutter on bit 10, as well as the effective rake angle of an individual cutter, only a single cutter 28 has been illustrated. The helical cutting path traveled by the cutter 28 is illustrated by solid line 30 extending the borehole 26 into formation 18.
The lone cutter 28 may have what would appear to be a negative rake angle relative to the horizontal surface 19′ of the formation 18. The angle θ formed between the horizontal and the planar cutting surface 29 of the cutter 28 is less than 90°. However, since bit 10 produces a downward linear motion as it drills the borehole 26, the effective path followed by the cutter 28 is generally downward at an angle of inclination related to the drilling rate of bit 10.
For example, a bit 10 having a cutter 28 rotating in a radius of six inches, at a drilling rate of ten feet per minute, and a rotational speed of 50 revolutions per minute results in the helical path 30 having an angle of inclination relative to horizontal of approximately 4°. Accordingly, if the cutting surface 29 of cutter 28 has an apparent angle of inclination relative to horizontal of approximately 86° (4° negative rake, relative to horizontal), then the cutting surface 29 has an effective angle of inclination, or effective rake, of precisely 90° and will be neither negatively nor positively raked. Such a rake angle may be termed a “neutral” rake or rake angle.
It should be recognized that the radial position of the cutter 28 is determinative as to the effective rake angle. For example, if the cutter 28 is positioned on the surface of the drill bit 10 at a radial distance of only three inches from the center, then its path has an angle of inclination relative to the horizontal of approximately 7°. The closer a cutter is positioned to the bit center, the greater the angle of inclination relative to the horizontal for a given rotational speed and given actual rake, and the greater the apparent negative rake of the cutter must be to obtain an effective negative rake angle.
In order to properly locate and orient cutter 28 and cutting surface 29 to have an effective positive, neutral or negative rake, it is desirable to estimate performance characteristics of the drill bit 10, as well as to determine the radial position of the cutter 28. For example, assuming that the cutter 28 is radially located six inches from the bit centerline and cutting surface 29 is inclined at an angle of 88° (2° negative rake relative to horizontal) and the drill bit 10 is being designed to achieve the drilling rate and rotational speed characteristics discussed immediately above, such that the helical path is inclined at an angle of 4°, then the effective rake angle of the cutting surface 29 is 92° (88°+4°=92°=2° positive rake). Thus, while the apparent angle of inclination or rake angle of the cutting surface 29 appears to be negative, the effective rake angle is actually positive. Such a design methodology would, of course, be performed for each cutter on a drill bit. It should be noted that not all boreholes have a vertical longitudinal axis. Therefore, it is appropriate to refer to the apparent angle of inclination as the angle formed between the planar cutting surface and a plane perpendicular to the longitudinal axis 24 of the bit. The “effective rake angle,” on the other hand, refers to the effective angle of inclination when the rotational speed and rate of penetration of bit 10 are taken into account. Accordingly, with the “effective rake angle” the angles of inclination of the cutting surface of drill bit cutters described hereinafter are measured and characterized as positive, negative or neutral relative to the intended helical cutting path 30 and not relative to horizontal (unless otherwise noted).
Referring now particularly to FIG. 4, therein is depicted a side elevation of a portion of a drill bit 10 with a positive rake cutter 12 and a negative rake cutter 14 affixed thereto. As noted above with respect to FIG. 3, the terms “positive” and “negative” rake are employed with reference to the effective angle between the cutting surface and the formation. The cutters 12 and 14 are secured in the bit body 16 in a conventional manner, such as by being furnaced therewith in the body of a metal matrix type bit, attached to a bit body via studs, or brazed or otherwise attached to the bit body 16. It should be understood that the present invention is applicable to any type of drill bit body, including matrix, steel and combinations thereof the latter including without limitation the use of a solid metal (such as steel) core with matrix blades, or a matrix core with hardfaced, solid metal blades. Stated another way, the present invention is not limited to any particular type of bit design or materials. In FIG. 3, the positive rake cutter 12 and the negative rake cutter 14 are illustrated removing formation material 18 in response to movement of the bit body 16 (and therefore cutters 12, 14), in a direction as indicated by arrow 21. The formation material 18 is in a plastic stress state and may be thought of as a flowing type material.
Cutters 12, 14 each preferably includes a generally planar cutting surface 20, 22. These cutting surfaces 20, 22 can be any of a variety of shapes known in the art. For the illustrated example, they may be considered as being of a conventional circular or disc shape. Cutting surfaces 20, 22 are preferably formed of a hard material, such as diamond or tungsten carbide, to resist wearing of the cutting surfaces caused by severe contact with the formation 18. In a particularly preferred embodiment, these cutting faces will each be formed of a diamond table, such as a single synthetic polycrystalline diamond PDC layer (including thermally stable PDC), a mosaic surface composed of a group of PDCs, or even a diamond film deposited by chemical vapor deposition techniques known in the art.
The angle of inclination of the cutting surfaces 20, 22 relative to the formation 18 is defined as positive or negative according to whether the angle formed therebetween is greater than or less than 90°, respectively, relative to the direction of cutter travel. For example, the cutting surface 20 of positive rake cutter 12 is illustrated having an angle of inclination or included angle ∝ relative to the formation of greater than 90°. That is to say, the bit face end or edge of planar cutting surface 20 leans away from the formation 18 with the leading edge of the cutting surface 20 contacting the formation 18. This positive rake of the cutting surface 20 encourages the cutter 12 to “dig in” to the formation 18 until the bit body 16 contacts the formation 18.
In contra-distinction thereto, the negative rake angle of cutting surface 22 of cutter 14 has an angle of inclination or included angle β relative to the formation that is less than 90° relative to the formation 18. The lower circumferential cutting edge of the cutting surface 22 engaging formation 18 trails the remaining portion of the cutting surface 22, such that the cutter 14 has a tendency to ride along the surface of the formation 18, making only a shallow cut therein. The cutting action caused by the cutter 14 is induced primarily by the weight on bit 10. Cutting surface 22 may also be oriented substantially perpendicularly to formation 18, thus being at a “neutral” rake, or at 0° backrake. In such an instance, cutting surface 22 will engage the formation 18 in a cutting capacity but will also ride on the formation, as is the case with negative rake cutters. It is believed that enhanced side rake of such a cutter will increase its cutting action by promoting clearance of formation cuttings from the cutter face.
The combined use of positive and negative or neutral rake cutters has a balancing effect that results in the positive rake cutter producing a shallower cut than it would otherwise do absent the negative or neutral rake cutter 14. Similarly, the negative or neutral rake cutter 14 produces a deeper cut than it would otherwise do absent the positive rake cutter 12. For example, while the positive rake cutter 12 encourages the drill bit 10 to be pulled into the formation 18, the negative or neutral rake cutter 14 urges the drill bit 10 to ride along the surface. Therefore, the combined effect of the positive and negative or neutral rake cutters 12, 14 is to allow a bit 10 to produce cuts at a depth somewhere between the full and minimal depth cuts which could be otherwise urged by the positive and negative rake cutters individually. It should be noted that the rake of positive rake cutter 12 may be more radical or significant in the present invention than might be expected or even possible without the cooperative arrangement of cutters 12 and 14, in order to aggressively initiate the cut into formation 18, rather than “riding” or “skating” thereon, and to cut without stalling, even in softer formations.
It has also recently been recognized that formation hardness has a profound affect on the performance of drill bits as measured by the ROP through the particular formation being drilled by a given drill bit. Furthermore, cutters installed in the face of a drill bit so as to have their respective cutting faces oriented at a given rake angle will likely produce ROPs that vary as a function of formation hardness. That is, if the cutters of a given bit are positioned so that their respective cutting faces are oriented with respect to a line perpendicular to the formation, as taken in the direction of intended bit rotation, so as to have a relatively large back (negative) rake angle, such cutters would be regarded as having relatively nonaggressive cutting action with respect to engaging and removing formation material at a given WOB. Contrastingly, cutters having their respective cutting faces oriented so as to have a relatively small back (negative) rake angle, a zero rake angle, or a positive rake angle would be regarded as having relatively aggressive cutting action at a given WOB with a cutting face having a positive rake angle being considered most aggressive and a cutting face having a small back rake angle being considered aggressive but less aggressive than a cutting face having a zero back rake angle and even less aggressive than a cutting face having a positive back rake angle.
It has further been observed that when drilling relatively hard formations, such as limestones, sandstones, and other consolidated formations, bits having cutters that provide relatively nonaggressive cutting action decrease the amount of unwanted reactive torque and provide improved tool face control, especially when engaged in directional drilling. Furthermore, if the particular formation being drilled is relatively soft, such as unconsolidated sand and other unconsolidated formations, such relatively nonaggressive cutters, due to the large depth-of-cut (DOC) afforded by drilling in soft formations, result in a desirable, relatively high ROP at a given WOB. However, such relatively nonaggressive cutters when encountering a relative hard formation, which it is very common to repeatedly encounter both soft and hard formations when drilling a single borehole, will experience a decreased ROP with the ROP generally becoming low in proportion to the hardness of the formation. That is, when using bits having nonaggressive cutters, the ROP generally tends to decrease as the formation becomes harder and increase as the formation becomes softer because the relatively nonaggressive cutting faces simply cannot “bite” into the formation at a substantial DOC to sufficiently engage and efficiently remove hard formation material at a practical ROP. That is, drilling through relative hard formations with nonaggressive cutting faces simply takes too much time.
Contrastingly, cutters that provide relatively aggressive cutting action excel at engaging and efficiently removing hard formation material, as the cutters generally tend to aggressively engage, or “bite,” into hard formation material. Thus, when using bits having aggressive cutters, the bit will often deliver a favorably high ROP, taking into consideration the hardness of the formation, and generally the harder the formation, the more desirable it is to have yet more aggressive cutters to better contend with the harder formations and to achieve a practical, feasible ROP therethrough.
It would be very helpful to the oil and gas industry, in particular, when using drag bits to drill boreholes through formations of varying degrees of hardness if drillers did not have to rely upon one drill bit designed specifically for hard formations, such as, but not limited to, consolidated sandstones and limestones and to rely upon another drill bit designed specifically for soft formations, such as, but not limited to, unconsolidated sands. That is, drillers frequently have to remove from the borehole, or trip out, a drill bit having cutters that excel at providing a high ROP in hard formations upon encountering a soft formation, or a soft “stringer,” in order to exchange the hard-formation drill bit with a soft formation drill bit, or vice versa, when encountering a hard formation, or hard “stringer,” when drilling primarily in soft formations.
Furthermore, it would be very helpful to the industry when conducting subterranean drilling operations and especially when conducting directional drilling operations, if methods were available for drilling which would allow a single drill bit be used in both relatively hard and relatively soft formations. Such a drill bit would thereby prevent an unwanted and expensive interruption of the drilling process to exchange formation-specific drill bits when drilling a borehole through both soft and hard formations. Such helpful drilling methods, if available, would result in providing a high, or at least an acceptable, ROP for the borehole being drilled through a variety of formations of varying hardness.
It would further be helpful to the industry to be provided with methods of drilling subterranean formations in which the cutting elements provided on a drag-type drill bit, for example, are able to efficiently engage the formation at an appropriate DOC suitable for the relative hardness of the particular formation being drilled at a given WOB, even if the WOB is in excess of what would be considered optimal for the ROP at that point in time. For example, if a drill bit provided with cutters having relatively aggressive cutting faces is drilling a relatively hard formation at a selected WOB suitable for the ROP of the bit through the hard formation and suddenly “breaks through” the relatively hard formation into a relatively soft formation, the aggressive cutters will likely overengage the soft formation. That is, the aggressive cutters will engage the newly encountered soft formation at a large DOC as a result of both the aggressive nature of the cutters and the still-present high WOB that was initially applied to the bit in order to drill through the hard formation at a suitable ROP but which is now too high for the bit to optimally engage the softer formation. Thus, the drill bit will become bogged down in the soft formation and will generate a TOB that in extreme cases will rotationally stall the bit and/or damage the cutters, the bit, or the drill string. Should a bit stall upon such a breakthrough occurring the driller must back off, or retract, the bit which was working so well in the hard formation but which has now stalled in the soft formation so that the drill bit may be set into rotational motion again and slowly eased forward to recontact and engage the bottom of the borehole to continue drilling. Therefore, if the drilling industry had methods of drilling wherein a bit could engage both hard and soft formations without generating an excessive amount of TOB while transitioning between formations of differing hardness, drilling efficiency would be increased and costs associated with drilling a wellbore would be favorably decreased.
Moreover, the industry would further benefit from methods of drilling subterranean formations in which the cutting elements provided on a drag bit are able to efficiently engage the formation so as to remove formation material at an optimum ROP yet not generate an excessive amount of unwanted TOB due to the cutting elements being too aggressive for the relative hardness of the particular formation being drilled.